Blue Dolphin Energy (BDCO) 10-Q 16 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2015shares
Document And Entity Information
Entity Registrant Name	BLUE DOLPHIN ENERGY CO
Entity Central Index Key	793,306
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	10,453,802
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2,015

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 1,518,359	$ 1,293,233
Restricted cash	5,834,197	1,008,514
Accounts receivable	7,833,519	8,340,303
Prepaid expenses and other current assets	1,045,893	771,458
Deposits	420,176	68,498
Inventory	5,620,827	$ 3,200,651
Deferred tax assets, current portion, net	2,892,459
Total current assets	25,165,430	$ 14,682,657
Total property and equipment, net	46,054,365	$ 37,371,075
Restricted cash, noncurrent	11,277,441
Surety bonds	1,667,000	$ 1,642,000
Debt issue costs, net	1,296,480	479,737
Trade name	303,346	303,346
Deferred tax assets, net	387,824	5,928,342
Total long-term assets	60,986,456	45,724,500
TOTAL ASSETS	86,151,886	60,407,157
CURRENT LIABILITIES
Accounts payable	$ 16,459,787	12,370,179
Accounts payable, related party		1,174,168
Asset retirement obligations, current portion	$ 38,644	85,846
Accrued expenses and other current liabilities	2,005,206	2,783,704
Interest payable, current portion	57,140	56,039
Long-term debt, current portion	$ 1,631,539	1,245,476
Deferred tax liabilities, net		168,236
Total current liabilities	$ 20,192,316	17,883,648
Long-term liabilities:
Asset retirement obligations, net of current portion	1,928,371	1,780,924
Deferred revenues and expenses	561,864	691,525
Long-term debt, net of current portion	28,948,021	10,808,803
Long-term interest payable, net of current portion	1,430,371	1,274,789
Total long-term liabilities	32,868,627	14,556,041
TOTAL LIABILITIES	53,060,943	$ 32,439,689
Commitments and contingencies (Note 21)
STOCKHOLDERS' EQUITY
Common stock ($0.01 par value, 20,000,000 shares authorized;10,603,802 and 10,599,444 shares issued at September 30, 2015 and December 31, 2014, respectively)	106,038	$ 105,995
Additional paid-in capital	36,738,737	36,718,781
Accumulated deficit	(2,953,832)	(8,057,308)
Treasury stock, 150,000 shares at cost	(800,000)	(800,000)
Total stockholders' equity	33,090,943	27,967,468
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 86,151,886	$ 60,407,157

Consolidated Balance Sheets (U3

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
STOCKHOLDERS' EQUITY
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	10,603,802	10,599,444
Common stock, shares outstanding	10,603,802	10,599,444
Treasury stock, shares	150,000	150,000

Consolidated Statements of Inco

Consolidated Statements of Income (Unaudited) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUE FROM OPERATIONS
Refined petroleum product sales	$ 54,924,070	$ 87,846,757	$ 174,830,292	$ 310,938,981
Tank rental revenue	286,892	282,516	860,676	847,548
Pipeline operations	45,925	56,900	119,882	178,793
Total revenue from operations	55,256,887	88,186,173	175,810,850	311,965,322
COST OF OPERATIONS
Cost of refined products sold	48,415,627	82,781,856	151,604,774	289,819,720
Refinery operating expenses	2,953,528	2,496,514	8,420,650	8,092,738
Joint Marketing Agreement profit share	1,435,376	1,094,383	4,812,674	2,334,487
Pipeline operating expenses	63,099	50,100	170,582	139,542
Lease operating expenses	(1,143)	7,041	20,271	21,037
General and administrative expenses	312,365	253,437	1,058,267	1,049,981
Depletion, depreciation and amortization	414,837	393,871	1,217,005	1,175,643
Accretion expense	52,720	53,731	158,655	158,264
Total cost of operations	53,646,409	87,130,933	167,462,878	302,791,412
Income from operations	1,610,478	1,055,240	8,347,972	9,173,910
OTHER INCOME (EXPENSE)
Easement, interest and other income	724,349	1,813	856,816	253,745
Interest expense	$ (382,191)	(214,407)	$ (1,322,562)	(675,586)
Loss on disposal of property and equipment		(4,400)		(4,400)
Total other income (expense)	$ 342,158	(216,994)	$ (465,746)	(426,241)
Income before income taxes	1,952,636	838,246	7,882,226	8,747,669
Income tax expense	(688,403)	(22,199)	(2,778,750)	(298,792)
Net income	$ 1,264,233	$ 816,047	$ 5,103,476	$ 8,448,877
Income per common share
Basic	$ 0.12	$ 0.08	$ 0.49	$ 0.81
Diluted	$ 0.12	$ 0.08	$ 0.49	$ 0.81
Weighted average number of common shares outstanding:
Basic	10,453,802	10,446,218	10,451,168	10,439,684
Diluted	10,453,802	10,446,218	10,451,168	10,439,684

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
OPERATING ACTIVITIES
Net income	$ 5,103,476	$ 8,448,877
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	1,217,005	1,175,643
Unrealized loss on derivatives	362,750	$ 26,150
Deferred taxes	2,479,823
Amortization of debt issue costs	517,652	$ 25,350
Accretion expense	158,655	158,264
Common stock issued for services	$ 19,999	75,001
Loss on disposal of assets		4,400
Changes in operating assets and liabilities
Accounts receivable	$ 506,784	2,058,624
Prepaid expenses and other current assets	(274,435)	152,655
Deposits and other assets	(1,711,073)	(490,838)
Inventory	(2,420,176)	(2,879,729)
Accounts payable, accrued expenses and other liabilities	2,916,973	(5,144)
Accounts payable, related party	(1,174,168)	(1,857,964)
Net cash provided by operating activities	7,703,265	6,891,289
INVESTING ACTIVITIES
Capital expenditures	(9,900,295)	$ (1,145,720)
Change in restricted cash for investing activities	(13,021,438)
Net cash used in investing activities	(22,921,733)	$ (1,145,720)
FINANCING ACTIVITIES
Proceeds from issuance of debt	25,000,000
Payments on long-term debt	(9,474,720)	$ (6,103,131)
Proceeds from notes payable	$ 3,000,000	2,000,000
Payments on notes payable		(216,182)
Change in restricted cash for financing activities	$ (3,081,686)	(678,498)
Net cash provided by (used in) financing activities	15,443,594	(4,997,811)
Net increase in cash and cash equivalents	225,126	747,758
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,293,233	434,717
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 1,518,359	1,182,475
Non-cash operating activities
Surety bond funded by seller of pipeline interest		850,000
Non-cash investing and financing activities:
New asset retirement obligations		300,980
Financing of capital expenditures via capital lease		536,635
Interest paid	$ 959,665	1,211,773
Income taxes paid	$ 139,500	$ 231,552

1. Organization

1. Organization	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Nature of Operations Blue Dolphin Energy Company ( http://www.blue-dolphin-energy.com Structure and Management We were formed as a Delaware corporation in 1986. We are currently controlled by Lazarus Energy Holdings, LLC (“LEH”), which owns approximately 81% of our common stock, par value $0.01 per share (the “Common Stock). LEH manages and operates all of our properties pursuant to an Operating Agreement (the “Operating Agreement”). Jonathan P. Carroll is Chairman of the Board of Directors (the “Board”), Chief Executive Officer and President of Blue Dolphin, as well as a majority owner of LEH. See “Note (10) Accounts Payable, Related Party,” “Note (13) Long-Term Debt,” and “Note (21) Commitments and Contingencies – Financing Agreements” of this report for additional disclosures related to the Operating Agreement, Jonathan P. Carroll, and LEH. Our operations are conducted through the following operating subsidiaries: • Lazarus Energy, LLC, a Delaware limited liability company (“LE”); • Lazarus Refining & Marketing, LLC, a Delaware limited liability company (“LRM”); • Blue Dolphin Pipe Line Company, a Delaware corporation; • Blue Dolphin Petroleum Company, a Delaware corporation; and • Blue Dolphin Services Co., a Texas corporation. See "Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Owned and Leased Assets” of this report for additional information regarding our operating subsidiaries.

2. Basis of Presentation

2. Basis of Presentation	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Basis of Presentation	We have prepared our unaudited consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”), as codified by the Financial Accounting Standards Board (the “FASB”) in its Accounting Standards Codification (“ASC”), and pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Our consolidated financial statements include Blue Dolphin and its subsidiaries. Significant intercompany transactions have been eliminated in the consolidation. In the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fair consolidated statements of income, financial position and cash flows. We believe that the disclosures are adequate and the presented information is not misleading. This report has been prepared in accordance with the SEC’s Form 10-Q instructions and therefore, certain information and footnote disclosures normally included in our annual audited financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the SEC’s rules and regulations.

3. Significant Accounting Polic

3. Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Significant Accounting Policies	The summary of significant accounting policies of Blue Dolphin is presented to assist in understanding our consolidated financial statements. Our consolidated financial statements and accompanying notes are representations of management who is responsible for its integrity and objectivity. These accounting policies conform to GAAP and have been consistently applied in the preparation of our consolidated financial statements. Use of Estimates We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated. Cash and Cash Equivalents Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents totaled $1,518,359 and $1,293,233 at September 30, 2015 and December 31, 2014, respectively. Restricted Cash Restricted cash totaled $5,834,197 and $1,008,514 at September 30, 2015 and December 31, 2014, respectively. Restricted cash, noncurrent totaled $11,277,441 and $0 at September 30, 2015 and December 31, 2014, respectively. Restricted cash primarily represents: (i) a construction contingency account under which Sovereign Bank, a Texas state bank (“Sovereign”) will fund contingencies, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a certificate of deposit held by Sovereign as security under a loan agreement. Restricted cash, noncurrent, represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks. See “Note (13) Long-Term Debt” of this report for additional disclosures related to loan agreements with Sovereign. Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary. Concentration of Risk Bank Accounts Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $18,017,488 and $1,113,977 at September 30, 2015 and December 31, 2014, respectively. Significant Customers Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (15) Concentration of Risk” of this report for additional disclosures related to significant customers. Inventory The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals. Inventory reflected for crude oil and condensate is nominal and represents line fill. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. See “Note (7) Inventory” of this report for additional disclosures related to our inventory. Derivatives We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, Genesis Energy, LLC (“Genesis”) may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash. Although these commodity futures contracts are not subject to hedge accounting treatment under FASB ASC guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of income. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of income using mark-to-market accounting. See “Note (19) Fair Value Measurement” and “Note (20) Inventory Risk Management” of this report for additional disclosures related to derivatives. Property and Equipment Refinery and Facilities Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances. Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the consolidated statements of income. For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service. We did not record any impairment of our refinery and facilities for the three and nine months ended September 30, 2015 and 2014. Oil and Gas Properties We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three and nine months ended September 30, 2015 and 2014. All leases associated with our oil and gas properties have expired. Pipelines and Facilities We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. Construction in Progress Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service. See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress. Intangibles – Other We have an acquisition-related intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014. Debt Issue Costs We have debt issue costs related to certain refinery and facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related asset accounts and expensed as interest expense. See “Note (9) Debt Issue Costs” of this report for additional disclosures related to debt issue costs. Revenue Recognition Refined Petroleum Products Revenue We sell jet fuel in nearby markets, and our intermediate products, including liquefied petroleum gas, naphtha, heavy oil-based mud blendstock (“HOBM”), and atmospheric gas oil (“AGO”), to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. Customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. Tank Rental Revenue Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. Easement Revenue Land easement revenue is recognized monthly as earned and is included in other income. Pipeline Transportation Revenue Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline. Deferred Revenue On February 5, 2014, we entered into an Asset Sale Agreement (the “Purchase Agreement”) with WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), whereby we reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline, and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for our benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure. Income Taxes We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. See “Note (17) Income Taxes” of this report for further information related to income taxes. Impairment or Disposal of Long-Lived Assets In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary. Asset Retirement Obligations FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. See “Note (12) Asset Retirement Obligations” of this report for additional information related to our AROs. Computation of Earnings Per Share We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of income and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. See “Note (18) Earnings Per Share” for additional information related to EPS. Stock-Based Compensation In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of income over the service period (generally the vesting period). Treasury Stock We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (14) Treasury Stock” for additional disclosures related to treasury stock. Reclassification We have reclassified certain insignificant prior period amounts related to our tank rental revenue to conform to our 2015 presentation. New Pronouncements Issued but Not Yet Effective FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. The following are recently issued, but not yet effective, accounting standards that may have an effect on our consolidated financial position, results of operations, or cash flows: • Revenue from Contracts with Customers In August 2015, FASB issued R evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, • Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern • Inventory (Topic 330): Simplifying the Measurement of Inventory • Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs • Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements Other new pronouncements issued but not effective until after September 30, 2015 are not expected to have a material impact on our financial position, results of operations or liquidity.

4. Business Segment Information

4. Business Segment Information	9 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
Business Segment Information	We have two reportable business segments: (i) Refinery Operations and (ii) Pipeline Transportation. Business activities related to our Refinery Operations business segment are conducted at the Nixon Facility. Business activities related to our Pipeline Transportation business segment are primarily conducted in the Gulf of Mexico through our Pipeline Assets and leasehold interests in oil and gas properties. Business segment information for the three months ended September 30, 2015 and 2014 (and at September 30, 2015 and 2014), was as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 55,210,962 $ 45,925 $ - $ 55,256,887 $ 88,129,273 $ 56,900 $ - $ 88,186,173 Less: cost of operations(1) (51,444,705 ) (114,675 ) (236,816 ) (51,796,196 ) (85,261,533 ) (110,872 ) (274,674 ) (85,647,079 ) Other non-interest income(2) - 62,500 660,000 722,500 - - - - Adjusted EBITDA 3,766,257 (6,250 ) 423,184 4,183,191 2,867,740 (53,972 ) (274,674 ) 2,539,094 Less: JMA Profit Share(3) (1,435,376 ) - - (1,435,376 ) (1,094,383 ) - - (1,094,383 ) EBITDA $ 2,330,881 $ (6,250 ) $ 423,184 $ 1,773,357 $ (53,972 ) $ (274,674 ) Depletion, depreciation and amortization (414,837 ) (393,871 ) Interest expense, net (380,342 ) (212,594 ) Income before income taxes 1,952,636 838,246 Income tax expense (688,403 ) (22,199 ) Net income $ 1,264,233 $ 816,047 Capital expenditures $ 3,640,801 $ - $ - $ 3,640,801 $ 815,849 $ - $ - $ 815,849 Identifiable assets(4) $ 79,442,106 $ 3,303,803 $ 3,405,977 $ 86,151,886 $ 57,520,835 $ 2,998,619 $ 523,533 $ 61,042,987 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue and the Grynberg Settlement Agreement. See “Part 1, Item 1. Financial Statements - Note (21) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this report for further discussion related to FLNG and Grynberg. (3) The Joint Marketing Agreement profit share (the “JMA Profit Share”) represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (21) Commitments and Contingencies – Genesis Agreements” and “Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for further discussion related to the Joint Marketing Agreement. (4) Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable, and recorded net assets. Business segment information for the nine months ended September 30, 2015 and 2014 (and at September 30, 2015 and 2014), was as follows: Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 175,690,968 $ 119,882 $ - $ 175,810,850 $ 311,786,529 $ 178,793 $ - $ 311,965,322 Less: cost of operations(1) (160,208,576 ) (296,291 ) (928,331 ) (161,433,198 ) (297,956,882 ) (355,645 ) (973,154 ) (299,285,681 ) Other non-interest income(2) - 187,500 660,000 847,500 - 208,333 - 208,333 Adjusted EBITDA 15,482,392 11,091 (268,331 ) 15,225,152 13,829,647 31,481 (973,154 ) 12,887,974 Less: JMA Profit Share(3) (4,812,674 ) - - (4,812,674 ) (2,334,487 ) - - (2,334,487 ) EBITDA $ 10,669,718 $ 11,091 $ (268,331 ) $ 11,495,160 $ 31,481 $ (973,154 ) Depletion, depreciation and amortization (1,217,005 ) (1,175,643 ) Interest expense, net (1,313,247 ) (630,175 ) Income before income taxes 7,882,226 8,747,669 Income tax expense (2,778,750 ) (298,792 ) Net income $ 5,103,476 $ 8,448,877 Capital expenditures $ 9,900,295 $ - $ - $ 9,900,295 $ 1,145,720 $ - $ - $ 1,145,720 Identifiable assets(4) $ 79,442,106 $ 3,303,803 $ 3,405,977 $ 86,151,886 $ 57,520,835 $ 2,998,619 $ 523,533 $ 61,042,987 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue and the Grynberg Settlement Agreement. See “Part 1, Item 1. Financial Statements - Note (21) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this report for further discussion related to FLNG and Grynberg. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (21) Commitments and Contingencies – Genesis Agreements” and “Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for further discussion related to the Joint Marketing Agreement. (4) Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable, and recorded net assets.

5. Prepaid Expenses and Other C

5. Prepaid Expenses and Other Current Assets	9 Months Ended
	Sep. 30, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid expenses and other current assets consisted of the following: September 30, December 31, 2015 2014 Prepaid related party operating expenses $ 712,688 $ - Prepaid insurance 196,305 156,558 Unrealized hedging gains 133,150 495,900 Prepaid listing fees 3,750 15,000 Prepaid professional fees - 104,000 $ 1,045,893 $ 771,458

6. Deposits

6. Deposits	9 Months Ended
	Sep. 30, 2015
Banking and Thrift [Abstract]
Deposits	Deposits consisted of the following: September 30, December 31, 2015 2014 Construction deposits $ 300,000 $ - Equipment deposits 100,463 48,785 Utility deposits 10,250 10,250 Rent deposits 9,463 9,463 $ 420,176 $ 68,498

7. Inventory

7. Inventory	9 Months Ended
	Sep. 30, 2015
Inventory Disclosure [Abstract]
Inventory	Inventory consisted of the following: September 30, December 31, 2015 2014 HOBM $ 3,044,646 $ 124,176 Jet fuel 1,557,847 2,631,546 AGO 403,875 224,007 Naphtha 362,049 194,688 Chemicals 216,208 - Crude oil and condensate 19,041 19,041 Propane 12,817 - LPG mix 4,344 7,193 $ 5,620,827 $ 3,200,651

8. Property, Plant and Equipmen

8. Property, Plant and Equipment, Net	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Net	Property, plant and equipment, net, consisted of the following: [Missing Graphic Reference]

9. Debt Issue Costs

9. Debt Issue Costs	9 Months Ended
	Sep. 30, 2015
Debt Issue Costs
Debt Issue Costs	Debt issue costs, net of accumulated amortization, totaled $1,296,480 and $479,737 at September 30, 2015 and December 31, 2014, respectively. Debt issue costs at September 30, 2015 related to loan agreements with Sovereign. Debt issue costs at December 31, 2014 related to a loan agreement with American First National Bank. Accumulated amortization totaled $22,781 and $211,244 at September 30, 2015 and December 31, 2014, respectively. Amortization expense, which is included in interest expense, was $17,086 and $8,450 for the three months ended September 30, 2015 and 2014, respectively. Amortization expense was $517,652 and $25,350 for the nine months ended September 30, 2015 and 2014, respectively. Amortization expense for the nine months ended September 30, 2015 included $456,287 related to writing off debt issue costs associated with the refinance of debt owed to American First National Bank. See “Note (13) Long-Term Debt” of this report for additional disclosures related to the loan agreements with Sovereign and American First National Bank.

10. Accounts Payable, Related P

10. Accounts Payable, Related Party	9 Months Ended
	Sep. 30, 2015
Payables and Accruals [Abstract]
Accounts Payable, Related Party	LEH manages and operates all of our properties pursuant to the Operating Agreement. For services rendered, LEH receives reimbursements and fees as follows: • Reimbursements – • Fees – For the three months ended September 30, 2015 and 2014, refinery operating expenses totaled $2,953,528 (approximately $2.66 per barrel of throughput) and $2,496,514 (approximately $2.94 per barrel of throughput), respectively. For the nine months ended September 30, 2015 and 2014, refinery operating expenses totaled $8,420,650 (approximately $2.73 per barrel of throughput) and $8,092,738 (approximately $2.78 per barrel of throughput), respectively. The Operating Agreement expires upon the earliest to occur of: (a) the date of the termination of the Joint Marketing Agreement pursuant to its terms, (b) August 12, 2018, or (c) upon written notice of either party to the Operating Agreement of a material breach of the Operating Agreement by the other party.

11. Accrued Expenses and Other

11. Accrued Expenses and Other Current Liabilities	9 Months Ended
	Sep. 30, 2015
Payables and Accruals [Abstract]
Accrued Expenses and Other Current Liabilities	Accrued expenses and other current liabilities consisted of the following: September 30, December 31, 2015 2014 Excise and income taxes payable $ 1,489,921 $ 1,228,411 Other payable 175,634 149,962 Genesis JMA Profit Share payable 162,470 521,739 Property taxes 92,002 - Board of director fees payable 85,179 345,000 Transportation and inspection - 190,000 Unearned revenue - 252,500 Insurance - 96,092 $ 2,005,206 $ 2,783,704

12. Asset Retirement Obligation

12. Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Refinery and Facilities Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Management believes that the refinery and facilities have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. Pipelines and Facilities and Oil and Gas Properties We have AROs associated with the dismantlement and abandonment in place of our pipelines and facilities, as well as the plugging and abandonment of our oil and gas properties. We recorded a discounted liability for the fair value of an ARO with a corresponding increase to the carrying value of the related long-lived asset at the time the asset was installed or placed in service. We amortize the amount added to property and equipment and recognize accretion expense in connection with the discounted liability over the remaining life of the asset. Plugging and abandonment costs for oil and gas properties and pipelines are recorded as information becomes available from operators to substantiate actual and/or probable costs. Abandonment costs that exceed the asset’s ARO liability are recorded as abandonment expense during the period incurred. For the three and nine months ended September 30, 2015 and 2014, we did not incur any abandonment expense related to our oil and gas properties. AROs on a roll-forward basis were as follows: September 30, December 31, 2015 2014 Asset retirement obligations, at the beginning of the period $ 1,866,770 $ 1,597,661 New asset retirement obligations and adjustments 49 300,980 Liabilities settled (58,459 ) (243,866 ) Accretion expense 158,655 211,995 1,967,015 1,866,770 Less: current portion of asset retirement obligations (38,644 ) (85,846 ) Long-term asset retirement obligations, at the end of the period $ 1,928,371 $ 1,780,924 The WBI transaction resulted in a $300,980 increase in our AROs related to the Pipeline Assets, which represents the fair value of the liability, and increased accretion expense throughout the remaining useful life of certain of the Pipeline Assets. For additional information related to the WBI Transaction, see “Note (3) Significant Accounting Policies – Revenue Recognition – Deferred Revenue” and “Note (21) Commitments and Contingencies – Supplemental Pipeline Bonds” of this report.

13. Long-Term Debt

13. Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consisted of the following: September 30, December 31, 2015 2014 Term Loan Due 2034 $ 24,822,362 $ - Term Loan Due 2016 3,000,000 - Notre Dame Debt 1,300,000 1,300,000 Term Loan Due 2017 1,109,962 1,638,898 Capital Leases 347,236 466,401 Refinery Note - 8,648,980 30,579,560 12,054,279 Less: current portion of long-term debt (1,631,539 ) (1,245,476 ) $ 28,948,021 $ 10,808,803 Term Loan Due 2034 We entered into a Loan and Security Agreement pursuant to a term loan in the principal amount of $25.0 million As a condition of the Term Loan Due 2034, Jonathan P. Carroll was required to guarantee r epayment Proceeds of the Term Loan Due 2034 were used to refinance approximately $8.5 million of debt owed to American First National Bank under the Refinery Note. Remaining proceeds are being used primarily to construct new petroleum storage tanks. The Term Loan Due 2034 is secured by: (i) a first lien on all Nixon Facility business assets (excluding accounts receivable and inventory), (ii) assignment of all Nixon Facility contracts, permits, and licenses, (iii) absolute assignment of Nixon Facility rents and leases, including tank rental income, (iv) a $1.0 million payment reserve account held by Sovereign, and (v) a pledge of $5.0 million of a life insurance policy on Jonathan P. Carroll. The Term Loan Due 2034 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type. Term Loan Due 2016 We entered into a Loan and Security Agreement with Sovereign as lender on June 22, 2015, for a term note in the principal amount of $3,000,000 (the “Term Loan Due 2016”). The Term Loan Due 2016 was amended on November 10, 2015, pursuant to a Loan Modification Agreement (the "November Loan Modification Agreement"). Under the November Loan Modification Agreement, the due date was extended to November 2016. The Term Loan Due 2016 accrues interest at the greater of the Wall Street Journal Prime Rate plus 2.75% or 6.00%. The Term Loan Due 2016 requires payment of interest with full payment of the outstanding principal due at maturity. The principal balance outstanding on the Term Loan Due 2016 was $3,000,000 and $0 at September 30, 2015 and December 31, 2014, respectively. Interest was accrued on the Term Loan Due 2016 in the amount of $15,500 and $0 at September 30, 2015 and December 31, 2014, respectively. As a condition of the Term Loan Due 2016, Jonathan P. Carroll was required to guarantee r epayment Proceeds of the Term Loan Due 2016 were used to purchase idle refinery equipment for the Nixon Facility. The Term Loan Due 2016 is secured by: (i) a first lien on the equipment that was purchased, (ii) a $1.5 million certificate of deposit at Sovereign, (iii) assignment of an easement agreement on land in Freeport, Texas (iv) a second lien on all LRM assets (excluding accounts receivable and inventory), and (v) a second lien and deed of trust on the Nixon Facility. The Term Loan Due 2016 contains representations and warranties, affirmative, restrictive, and financial covenants, as well as events of default which are customary for credit facilities of this type. Notre Dame Debt We entered into a loan with Notre Dame Investors, Inc. as evidenced by a Promissory Note in the original principal amount of $8.0 million, which is currently held by John Kissick (the “Notre Dame Debt”). The Notre Dame Debt matures in January 2017, and accrues interest at a rate of 16.00%. The principal balance outstanding on the Notre Dame Debt was $1,300,000 at September 30, 2015 and December 31, 2014. Interest was accrued on the Notre Dame Debt in the amount of $1,430,371 and $1,274,789 at September 30, 2015 and December 31, 2014, respectively. The Notre Dame Debt is secured by a Deed of Trust, Security Agreement and Financing Statements (the “Subordinated Deed of Trust”), which encumbers the Nixon Facility and general assets of LE. There are no financial maintenance covenants associated with the Notre Dame Debt. Pursuant to a Subordination Agreement dated June 22, 2015, the holder of the Notre Dame Debt agreed to subordinate its interest and liens on the Nixon Facility and general assets of LE first in favor of Sovereign as holder of the Term Loan Due 2034 and second in favor of GEL. See “Note (21) Commitments and Contingencies” of this report for additional disclosures related to the Genesis Agreements. Term Loan Due 2017 We entered into a Loan and Security Agreement with Sovereign on May 2, 2014, for a term loan facility in the principal amount of $2.0 million (the “Term Loan Due 2017”). The Term Loan Due 2017 was amended on March 25, 2015, pursuant to a Loan Modification Agreement (the “March Loan Modification Agreement”). Under the March Loan Modification Agreement, the interest rate was modified to be the greater of the U.S. Prime Rate plus 2.75% or 6.00% and the due date was extended to March 2017. Pursuant to the March Loan Modification Agreement, the monthly payment due under the Term Loan Due 2017 is $61,665 plus interest. The principal balance outstanding on the Term Loan Due 2017 was $1,109,962 and $1,638,898 at September 30, 2015 and December 31, 2014, respectively. Interest was accrued on the Term Loan Due 2017 in the amount of $5,550 and $8,470 at September 30, 2015 and December 31, 2014, respectively. As a condition of the Term Loan Due 2017, Jonathan P. Carroll was required to guarantee r epayment The proceeds of the Term Loan Due 2017 were used primarily to finance costs associated with refurbishment of the Nixon Facility’s naphtha stabilizer and depropanizer units. The Term Loan Due 2017 is: (i) subject to a financial maintenance covenant pertaining to debt service coverage ratio and (ii) secured by the assignment of certain leases of LRM and assets of LEH. See “Note (10) Accounts Payable, Related Party” of this report for additional disclosures related to LEH. Capital Leases We entered into a 36 month “build-to-suit” capital lease on August 7, 2014, for the purchase of new boiler equipment for the Nixon Facility. The equipment was delivered in December 2014 and the cost was added to construction in progress. Once placed in service, the equipment will be reclassified to refinery and facilities and depreciation will begin. The capital lease requires a quarterly payment in the amount of $42,996. Capital lease obligations totaled $347,236 and $466,401 at September 30, 2015 and December 31, 2014, respectively. Interest was accrued on capital leases in the amount of $2,988 and $0 at September 30, 2015 and December 31, 2014, respectively. The following is a summary of equipment held under long-term capital leases: September 30, December 31, 2015 2014 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598 Refinery Note We entered into a Loan Agreement with First International Bank on September 29, 2008, in the principal amount of $10.0 million (the “Refinery Note”). The Refinery Note was subsequently acquired by American First National Bank. The Refinery Note matured in October 2028 and accrued interest at a rate based on the U.S. Prime Rate plus 2.25%. The principal balance outstanding on the Refinery Note was $0 and $8,648,980 at September 30, 2015 and December 31, 2014, respectively. Interest was accrued on the Refinery Note in the amount of $0 and $47,569 at September 30, 2015 and December 31, 2014, respectively. All amounts due and outstanding under the Refinery Note were repaid in June 2015.

14. Treasury Stock

14. Treasury Stock	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Treasury Stock	At September 30, 2015 and December 31, 2014, we had 150,000 shares of treasury stock.

15. Concentration of Risk

15. Concentration of Risk	9 Months Ended
	Sep. 30, 2015
Risks and Uncertainties [Abstract]
Concentration of Risk	Key Supplier Under the Crude Oil and Supply Throughput Services Agreement dated August 12, 2011 (the “Crude Supply Agreement”), GEL is our exclusive supplier of crude oil and condensate. We have the ability to purchase crude oil and condensate from other suppliers with the prior consent of GEL. The initial term was to expire on August 12, 2014. However, on October 30, 2013, we entered into a Letter Agreement Regarding Certain Advances and Related Agreements with GEL and Milam Services, Inc. (“Milam”)(the “October 2013 Letter Agreement”), effective October 24, 2013. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Crude Supply Agreement and GEL agreed to automatically renew the Crude Supply Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice. Significant Customers For the three months ended September 30, 2015, we had 5 customers that accounted for approximately 81% of our refined petroleum products sales. These 5 customers represented approximately $5.7 million in accounts receivable at September 30, 2015. For the three months ended September 30, 2014, we had 3 customers that accounted for approximately 71% of our refined petroleum products sales. These 3 customers represented approximately $6.4 million in accounts receivable at September 30, 2014. For the nine months ended September 30, 2015, we had 3 customers that accounted for approximately 55% of our refined petroleum products sales. These 3 customers represented approximately $4.4 million in accounts receivable at September 30, 2015. For the nine months ended September 30, 2014, we had 4 customers that accounted for approximately 84% of our refined petroleum products sales. These 4 customers represented approximately $7.7 million in accounts receivable at September 30, 2014. Refined Petroleum Product Sales All of our refined petroleum products are currently sold in the United States. The following table summarizes total refined petroleum product sales by distillation (from light to heavy): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 LPG mix $ 617,715 1.1 % $ 146,452 0.2 % $ 909,207 0.5 % $ 670,473 0.2 % Naphtha 11,218,381 20.4 % 19,195,974 21.8 % 38,048,064 21.8 % 73,061,235 23.5 % Jet fuel 17,782,534 32.4 % 25,978,551 29.6 % 51,713,507 29.6 % 65,616,193 21.1 % NRLM - 0.0 % - 0.0 % - 0.0 % 62,729,476 20.2 % HOBM 9,609,536 17.5 % 22,094,185 25.1 % 40,640,975 23.2 % 29,321,261 9.4 % Reduced Crude 50,407 0.1 % - 0.0 % 50,407 0.0 % - 0.0 % AGO 15,645,497 28.5 % 20,431,595 23.3 % 43,468,132 24.9 % 79,540,343 25.6 % $ 54,924,070 100.0 % $ 87,846,757 100.0 % $ 174,830,292 100.0 % $ 310,938,981 100.0 % On May 31, 2014, we ceased production of NRLM, a transportation-related diesel fuel product. On June 1, 2014, we began producing HOBM, a non-transportation lubricant blend product. The shift in product slate from NRLM to HOBM was the result of the Environmental Protection Agency’s (the “EPA’s”) phased-in requirements for small refineries to reduce the sulfur content in transportation-related diesel fuel, such as NRLM, to a maximum of 15 ppm sulfur by June 1, 2014. “Topping units,” like the Nixon Facility, typically lack a desulfurization process unit to lower sulfur content levels within the range required by the EPA’s recently implemented fuel quality standards, and integration of such a unit generally requires additional permitting and significant capital upgrades. We can produce and sell a low sulfur diesel as a feedstock to other refineries and blenders in the United States and as a finished petroleum product to other countries.

16. Leases

16. Leases	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Leases	Our company headquarters is located in downtown Houston, Texas. We lease 13,878 square feet of office space, 7,389 square feet of which is used and paid for by LEH. The office lease has a 10 year term expiring in 2017, includes free rent periods and escalating rent payment provisions, and requires payment of a portion of related actual operating expenses. Rent expense is recognized on a straight-line basis. For the three months ended September 30, 2015 and 2014, rent expense totaled $29,857 and $26,129, respectively. For the nine months ended September 30, 2015 and 2014, rent expense totaled $112,746 and $77,787, respectively.

17. Income Taxes

17. Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax Expense Our income tax expense consisted of the following: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Current: Federal $ (37,620 ) $ (1,395 ) $ (122,863 ) $ (152,759 ) State (36,102 ) (20,804 ) (148,656 ) (146,033 ) Deferred: Federal (614,681 ) - (2,507,231 ) - State - - - - $ (688,403 ) $ (22,199 ) $ (2,778,750 ) $ (298,792 ) The state of Texas has a Texas margins tax (“TMT”), which is a form of business tax imposed on gross margin to replace the state’s prior franchise tax structure. Although TMT is imposed on an entity’s gross margin rather than on its net income, certain aspects of TMT make it similar to an income tax. Deferred Income Taxes Under Section 382 of the Internal Revenue Code of 1986, as amended (“IRC Section 382”), a corporation that undergoes an “ownership change” is subject to limitations on its use of pre-change NOL carryforwards to offset future taxable income. Within the meaning of IRC Section 382, an “ownership change” occurs when the aggregate stock ownership of certain stockholders (generally 5% shareholders, applying certain look-through rules) increases by more than 50 percentage points over such stockholders' lowest percentage ownership during the testing period (generally three years). In general, the annual use limitation equals the aggregate value of common stock at the time of the ownership change multiplied by a specified tax-exempt interest rate. We experienced ownership changes in 2005 in connection with a series of private placements, and in 2012 as a result of a reverse acquisition. The 2012 ownership change will subject NOL carryforwards to an annual use limitation, which will significantly reduce our ability to use them to offset taxable income in periods following the 2012 ownership change. The amount of NOLs subject to such limitations is approximately $18.7 million. As a result of the limitation under IRC Section 382, the annual use limitation is $638,196 per year, the effect of which will result in approximately $6.7 million in NOL carryforwards expiring unused. At September 30, 2015, approximately $3.3 million of net deferred tax asset remained available for future use, reflecting use of approximately $5.4 million of net operating loss carryforwards through the period. At September 30, 2015, approximately $9.6 million of NOLs generated prior to the 2012 ownership change remain available for future use. At September 30, 2015, approximately $7.9 million of NOLs generated subsequent to the 2012 ownership change remained available for future use and are not subject to an annual use limitation under IRC Section 382. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes. The following table shows significant components of our deferred tax assets and liabilities: September 30, December 31, 2015 2014 Deferred tax assets: Net operating loss and capital loss carryforwards $ 8,221,505 $ 10,067,144 Start-up costs (Nixon Facility) 1,545,033 1,648,036 Asset retirement obligations liability/deferred revenue 859,819 869,821 AMT credit and other 236,389 85,467 Total deferred tax assets 10,862,746 12,670,468 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (45,271 ) (168,606 ) Basis differences in property and equipment (5,220,754 ) (4,425,318 ) Total deferred tax liabilities (5,312,141 ) (4,640,040 ) Deferred tax assets, net 5,550,605 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,280,283 $ 5,760,106 The following table shows our current and noncurrent deferred tax assets (liabilities): September 30, December 31, 2015 2014 Current deferred tax liabilities $ 5,162,781 $ (168,236 ) Noncurrent deferred tax assets, net 387,824 8,198,664 Deferred tax assets, net 5,550,605 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,280,283 $ 5,760,106 Valuation Allowance As of each reporting date, management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets. As of September 30, 2015 and December 31, 2014, management determined that sufficient positive evidence existed to conclude that it was more likely than not that net deferred tax assets of approximately $3.3 million and $5.8 million, respectively, were realizable, and as a result, reflected a valuation allowance accordingly. Uncertain Tax Positions We have adopted the provisions of the FASB ASC guidance on accounting for uncertainty in income taxes. The guidance clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The standard also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. As part of this guidance, we record income tax related interest and penalties, if applicable, as a component of the provision for income tax benefit (expense). However, there were no amounts recognized relating to interest and penalties in the consolidated statements of income for the three and nine months ended September 30, 2015 and 2014. Furthermore, none of our federal and state income tax returns are currently under examination by the Internal Revenue Service (“IRS”) or state authorities. As of September 30, 2015, fiscal years 2011 and later remain subject to examination by the IRS and fiscal years 2009 and later remain subject to examination by the state of Texas. We believe there are no uncertain tax positions for both federal and state income taxes.

18. Earnings Per Share

18. Earnings Per Share	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Earnings Per Share	The following table provides reconciliation between basic and diluted income per share: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net income $ 1,264,233 $ 816,047 $ 5,103,476 $ 8,448,877 Basic and diluted income per share $ 0.12 $ 0.08 $ 0.49 $ 0.81 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,453,802 10,446,218 10,451,168 10,439,684 Diluted EPS is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding. Diluted EPS for the three and nine months ended September 30, 2015 and 2014 was the same as basic EPS as there were no stock options or other dilutive instruments outstanding.

19. Fair Value Measurement

19. Fair Value Measurement	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurement	We have determined the fair value of certain assets and liabilities through the application of fair value measurements and disclosures, which establishes a framework for measuring fair value. We are subject to gains or losses on certain financial assets based on our various agreements and understandings with Genesis. Pursuant to these agreements and understandings, Genesis may execute the purchase and sale of certain financial instruments for the purpose of economically hedging certain commodity price risks associated with our refined petroleum products and, over time, this program may also include mitigating certain risks associated with the purchase of crude oil and condensate. These financial instruments are direct contractual obligations of Genesis and not us. However, under our agreement with Genesis, we financially benefit from any gains and financially bear any losses associated with the purchase and/or sale of such financial instruments by Genesis. Because such instruments represent embedded derivatives for the purpose of financial reporting, we account for such embedded derivatives in our financial records by utilizing the market approach when measuring fair value of our financial instruments (typically in current assets and/or liabilities, as discussed below). The market approach uses prices and other relevant information generated by such market transactions executed on our behalf involving identical or comparable assets or liabilities. Generally accepted accounting principles establish a framework for measuring the fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The fair value hierarchy consists of the following three levels: Level 1 Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs, which are derived principally from or corroborated by observable market data. Level 3 Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable and cannot be corroborated by market data or other entity-specific inputs. The carrying amounts of accounts receivable, accounts payable, and accrued liabilities approximated their fair values at September 30, 2015 and December 31, 2014 due to their short-term maturities. The fair value of our short and long-term debt at September 30, 2015 and December 31, 2014 was $30,579,560 and $12,054,279, respectively. The fair value of our debt was determined using a Level 3 hierarchy. The following table represents our assets and liabilities measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 and the basis for the measurement: Fair Value Measurement at September 30, 2015 Using Financial assets (liabilities): Carrying Value at September 30, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 133,150 $ 133,150 $ - $ - Fair Value Measurement at December 31, 2014 Using Financial assets (liabilities): Carrying Value at December 31, 2014 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 495,900 $ 495,900 $ - $ - Carrying amounts of commodity contracts executed by Genesis are reflected as other current assets or other current liabilities in our consolidated balance sheets.

20. Inventory Risk Management

20. Inventory Risk Management	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Inventory Risk Management	Under our inventory risk management policy, Genesis may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations in our inventory. The physical inventory volumes are not exchanged, and these contracts are net settled by Genesis with cash. The fair value of these contracts is reflected in our consolidated balance sheets and the related net gain or loss is recorded within cost of refined products sold in our consolidated statements of income. Quoted prices for identical assets or liabilities in active markets (Level 1) are considered to determine the fair values for the purpose of marking to market the financial instruments at each period end. Commodity transactions are executed by Genesis to minimize transaction costs, monitor consolidated net exposures, and allow for increased responsiveness to changes in market factors. Genesis may, but is not required to, initiate an economic hedge on our refined petroleum products when our inventory levels exceed targeted levels (currently 1.5 days production). Although the decision to enter into a futures contract is made solely by Genesis, Genesis typically confers with management as part of Genesis’ decision making process. Due to mark-to-market accounting during the term of the commodity contracts, significant unrealized non-cash net gains and losses could be recorded in our results of operations. Additionally, Genesis may be required to collateralize any mark-to-market losses on outstanding commodity contracts. As of September 30, 2015, we had the following obligations based on futures contracts of refined petroleum products and crude oil that were entered into as economic hedges through Genesis. The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels): Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2015 2016 2017 Refined petroleum products and crude oil - net short positions 155,000 - - The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at September 30, 2015 and December 31, 2014: Fair Value Asset Derivatives Balance Sheets Location September 30, 2015 December 31, 2014 Prepaid expenses and other current assets (accrued expenses and other Commodity contracts current liabilities) $ 133,150 $ 495,900 The following table provides the effect of derivative instruments in our consolidated statements of income for the three months ended September 30, 2015 and 2014: Gain (Loss) Recognized Three Months Ended September 30, Nine Months Ended September 30, Derivatives Statements of Operations Location 2015 2014 2015 2014 Commodity contracts Cost of refined products sold $ 2,205,291 $ 396,271 $ 1,762,582 $ (12,438 )

21. Commitments and Contingenci

21. Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Operating Agreement See “Note (10) Accounts Payable, Related Party” of this report for additional disclosures related to the Operating Agreement. Genesis Agreements We were previously subject to three agreements with Genesis and its affiliates. Under the Construction and Funding Agreement, Milam committed funding for the Nixon Facility’s start-up refurbishment. Payments under the Construction and Funding Agreement began in the first quarter of 2012, when the Nixon Facility was placed in service. As a result of our repayment of amounts due to Milam under the Construction and Funding Agreement in May 2014, we now receive up to 80% of the Gross Profits as our Profit Share under the Joint Marketing Agreement. Our relationship with Genesis and its affiliates is currently governed by two agreements, as follows: ● Joint Marketing Agreement ● We are entitled to receive weekly payments to cover direct expenses in operating the Nixon Facility (the “Operations Payments”) in an amount not to exceed $750,000 per month plus the amount of any accounting fees, if incurred, not to exceed $50,000 per month. We assigned our rights to weekly payments and reimbursement of accounting fees under the Joint Marketing Agreement to LEH pursuant to the Operating Agreement. If Gross Profits are insufficient to cover Operations Payments, then GEL may: (i) reduce Operations Payments by an amount representing the difference between the Operations Payments and the Gross Profits for such monthly period, or (ii) provide the Operations Payments with such Operations Payments being considered deficit amounts owing to GEL. If Gross Profits are negative, then we are not entitled to receive Operations Payments and GEL may recoup any losses sustained by a special allocation of 80% of Gross Profits until such losses are covered in full, after which the prevailing Gross Profits allocation shall be reinstated; and ● GEL is entitled to receive an administrative fee in the amount of $150,000 per month relating to the performance of its obligations under the Joint Marketing Agreement (the “Performance Fee”). GEL shall be paid 30% of the remaining Gross Profit up to $600,000 (the “Threshold Amount”) as the GEL Profit Share and we shall be paid 70% of the remaining Gross Profit as our Profit Share. Any amount of remaining Gross Profit that exceeds the Threshold Amount for such calendar month shall be paid to GEL and us in the following manner: (i) GEL shall be paid 20% of the remaining Gross Profits over the Threshold Amount as the GEL Profit Share and (ii) we shall be paid 80% of the remaining Gross Profits over the Threshold Amount as our Profit Share. The GEL Profit Share plus the Performance Fee are collectively referred to in this report as the JMA Profit Share. The Joint Marketing Agreement contains negative covenants that restrict our actions under certain circumstances. For example, we are prohibited from making any modifications to the Nixon Facility or entering into any contracts with third-parties that would materially affect or impair GEL’s or its affiliates’ rights under the agreements set forth above. The Joint Marketing Agreement had an initial term of three years expiring on August 12, 2014. In accordance with the terms of the October 2013 Letter Agreement, we agreed not to terminate the Joint Marketing Agreement and GEL agreed to automatically renew the Joint Marketing Agreement at the end of the initial term for successive one year periods until August 12, 2019, unless sooner terminated by GEL with 180 days prior written notice; and ● Crude Supply Agreement Pursuant to a Letter Agreement Regarding Subordination of GEL Transaction Documents dated June 4, 2015, we, among other things, assigned our rights to payments under the Joint Marketing Agreement and Crude Supply Agreement as collateral in favor of Sovereign as lender and lienholder pursuant to the Term Loan Due 2034. See “Note (13) Long-Term Debt” of this report for further discussion related to the Term Loan Due 2034. FLNG Master Easement Agreement Pursuant to a Master Easement Agreement dated December 11, 2013, we provide FLNG Land II, Inc., a Delaware corporation (“FLNG”) with: (i) uninterrupted pedestrian and vehicular ingress and egress to and from State Highway 332, across certain of our property to certain property of FLNG (the “Access Easement”) and (ii) a pipeline easement and right of way across certain of our property to certain property owned by FLNG (the “Pipeline Easement” and together with the Access Easement, the “Easements”). Under the agreement, FLNG will make payments to us in the amount of $500,000 in October of each year through 2019. Thereafter, FLNG will make payments to us in the amount of $10,000 in October of each year for so long as FLNG desires to use the Access Easement. Supplemental Pipeline Bonds We are required to satisfy supplemental pipeline bonding requirements of the Bureau of Ocean Energy Management (“BOEM”) with regard to certain pipelines that we operate in federal waters of the Gulf of Mexico. These supplemental pipeline bonding requirements are intended to secure our performance of plugging and abandonment obligations with respect to these pipelines. Once plugging and abandonment work has been completed, the collateral backing the supplemental pipeline bonds will be released. In August 2006, we secured a $700,000 supplemental pipeline bond for Right-of-Way Number OCS-G 01381. On February 5, 2014, we entered into a Purchase Agreement whereby we reacquired WBI’s 1/6th interest in the Pipeline Assets effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. The $850,000 in cash was used to: (i) increase the supplemental pipeline bond for Right-of-Way Number OCS-G 01381 by $205,000, and (ii) secure a $645,000 supplemental pipeline bond for Right-of-Way Number OCS-G 08606. In December 2014, we completed plugging and abandonment work for Right-of-Way Number OCS-G 08606. In February 2015, we requested that BOEM release the cash-backed collateral for this supplemental pipeline bond. Although BOEM indicated that the bond was cancelled, as of the date of this report we were awaiting release of the collateral. There can be no assurance that BOEM will not require additional supplemental pipeline bonds related to our other pipeline right-of-ways. Financing Agreements See “Note (13) Long-Term Debt” of this report for additional disclosures related to financing agreements. Grynberg Settlement Agreement During the third quarter of 2015, management reevaluated its estimated zero gain contingency related to a nearly two decades-old case involving Jack J. Grynberg and several defendants in the oil and gas industry, including Blue Dolphin Pipe Line Company (the “Grynberg Matter”). New developments in the Grynberg Matter resulted in a final Mutual Release Agreement and Withdrawal of All Qui Tam Claims Legal Matters From time to time we are subject to various lawsuits, claims, mechanics liens, and administrative proceedings that arise out of the normal course of business. Management does not believe that liens, if any, will have a material adverse effect on our results of operations. Health, Safety and Environmental Matters All of our operations and properties are subject to extensive federal, state, and local environmental, health, and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances; the emission and discharge of materials into the environment; waste management; characteristics and composition of jet fuel and other products; and the monitoring, reporting and control of greenhouse gas emissions. Our operations also require numerous permits and authorizations under various environmental, health, and safety laws and regulations. Failure to obtain and comply with these permits or environmental, health, or safety laws generally could result in fines, penalties or other sanctions, or a revocation of our permits.

3. Significant Accounting Pol27

3. Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Use of Estimates	We have made a number of estimates and assumptions related to the reporting of our consolidated assets and liabilities and to the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with GAAP. While we believe our current estimates are reasonable and appropriate, actual results could differ from those estimated.
Cash and Cash Equivalents	Cash and cash equivalents represent liquid investments with an original maturity of three months or less. Cash balances are maintained in depository and overnight investment accounts with financial institutions that, at times, may exceed insured deposit limits. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts. Cash and cash equivalents totaled $1,518,359 and $1,293,233 at September 30, 2015 and December 31, 2014, respectively.
Restricted Cash	Restricted cash totaled $5,834,197 and $1,008,514 at September 30, 2015 and December 31, 2014, respectively. Restricted cash, noncurrent totaled $11,277,441 and $0 at September 30, 2015 and December 31, 2014, respectively. Restricted cash primarily represents: (i) a construction contingency account under which Sovereign Bank, a Texas state bank (“Sovereign”) will fund contingencies, (ii) a payment reserve account held by Sovereign as security for payments under a loan agreement, and (iii) a certificate of deposit held by Sovereign as security under a loan agreement. Restricted cash, noncurrent, represents a disbursement account under which Sovereign will make payments for construction related expenses to build new petroleum storage tanks. See “Note (13) Long-Term Debt” of this report for additional disclosures related to loan agreements with Sovereign.
Accounts Receivable, Allowance for Doubtful Accounts and Concentration of Credit Risk	Accounts receivable are customer obligations due under normal trade terms. The allowance for doubtful accounts represents our estimate of the amount of probable credit losses existing in our accounts receivable. We have a limited number of customers with individually large amounts due on any given date. Any unanticipated change in any one of these customers’ credit worthiness or other matters affecting the collectability of amounts due from such customers could have a material adverse effect on our results of operations in the period in which such changes or events occur. We regularly review all of our aged accounts receivable for collectability and establish an allowance for individual customer balances as necessary.
Concentration of Risk	Bank Accounts Financial instruments that potentially subject us to concentrations of risk consist primarily of cash, trade receivables and payables. We maintain our cash balances at financial institutions located in Houston, Texas. In the United States, the Federal Deposit Insurance Corporation (the “FDIC”) insures certain financial products up to a maximum of $250,000 per depositor. We had cash balances in excess of the FDIC insurance limit per depositor in the amount of $18,017,488 and $1,113,977 at September 30, 2015 and December 31, 2014, respectively. Significant Customers Customers of our refined petroleum products include distributors, wholesalers, and refineries primarily in the lower portion of the Texas Triangle (the Houston - San Antonio - Dallas/Fort Worth area). We have bulk term contracts, including month-to-month, six months, and up to five year terms in place with most of our customers. Certain of our contracts require us to sell fixed quantities and/or minimum quantities of intermediate and finished petroleum products and many of these arrangements are subject to periodic renegotiation, which could result in us receiving higher or lower relative prices for our refined petroleum products. See “Note (15) Concentration of Risk” of this report for additional disclosures related to significant customers.
Inventory	The nature of our business requires us to maintain inventory, which primarily consists of refined petroleum products and chemicals. Inventory reflected for crude oil and condensate is nominal and represents line fill. Our overall inventory is valued at lower of cost or market with costs being determined by the average cost method. If the market value of our refined petroleum product inventories declines to an amount less than our average cost, we record a write-down of inventory and an associated adjustment to cost of refined products sold. See “Note (7) Inventory” of this report for additional disclosures related to our inventory.
Derivatives	We are exposed to commodity prices and other market risks including gains and losses on certain financial assets as a result of our inventory risk management policy. Under our inventory risk management policy, Genesis Energy, LLC (“Genesis”) may, but is not required to, use commodity futures contracts to mitigate the change in value for certain of our refined petroleum product inventories subject to market price fluctuations. The physical inventory volumes are not exchanged and these contracts are net settled with cash. Although these commodity futures contracts are not subject to hedge accounting treatment under FASB ASC guidance, we record the fair value of these Genesis hedges in our consolidated balance sheet each financial reporting period because of contractual arrangements with Genesis under which we are effectively exposed to the potential gains or losses. We recognize all commodity hedge positions as either current assets or current liabilities in our consolidated balance sheets and those instruments are measured at fair value. Changes in the fair value from financial reporting period to financial reporting period are recognized in our consolidated statements of income. Net gains or losses associated with these transactions are recognized within cost of refined products sold in our consolidated statements of income using mark-to-market accounting. See “Note (19) Fair Value Measurement” and “Note (20) Inventory Risk Management” of this report for additional disclosures related to derivatives.
Property and Equipment	Refinery and Facilities Additions to refinery and facilities are capitalized. Expenditures for repairs and maintenance are expensed as incurred and are included as operating expenses under the Operating Agreement. Management expects to continue making improvements to the Nixon Facility based on technological advances. Refinery and facilities are carried at cost. Adjustment of the asset and the related accumulated depreciation accounts are made for refinery and facilities’ retirements and disposals, with the resulting gain or loss included in the consolidated statements of income. For financial reporting purposes, depreciation of refinery and facilities is computed using the straight-line method using an estimated useful life of 25 years beginning when the refinery and facilities are placed in service. We did not record any impairment of our refinery and facilities for the three and nine months ended September 30, 2015 and 2014. Oil and Gas Properties We account for our oil and gas properties using the full-cost method of accounting, whereby all costs associated with acquisition, exploration and development of oil and gas properties, including directly related internal costs, are capitalized on a cost center basis. Amortization of such costs and estimated future development costs are determined using the unit-of-production method. Our oil and gas properties had no production during the three and nine months ended September 30, 2015 and 2014. All leases associated with our oil and gas properties have expired. Pipelines and Facilities We record pipelines and facilities at cost less any adjustments for depreciation or impairment. Depreciation is computed using the straight-line method over estimated useful lives ranging from 10 to 22 years. In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. Construction in Progress Construction in progress expenditures, which relate to construction and refurbishment activities at the Nixon Facility, are capitalized as incurred. Depreciation begins once the asset is placed in service. See “Note (8) Property, Plant and Equipment, Net” of this report for additional disclosures related to our refinery and facilities, oil and gas properties, pipelines and facilities, and construction in progress.
Intangibles - Other	We have an acquisition-related intangible asset consisting of the Blue Dolphin trade name in the amount of $303,346. We have determined our trade name to have an indefinite useful life. We account for other intangible assets under FASB ASC guidance related to intangibles, goodwill and other. Under the guidance, we test intangible assets with indefinite lives annually for impairment. Management performed its regular annual impairment testing of trade name in the fourth quarter of 2014. Upon completion of that testing, we determined that no impairment was necessary as of December 31, 2014.
Debt Issue Costs	We have debt issue costs related to certain refinery and facilities debt. Debt issue costs are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. When a loan is paid in full, any unamortized financing costs are removed from the related asset accounts and expensed as interest expense. See “Note (9) Debt Issue Costs” of this report for additional disclosures related to debt issue costs.
Revenue Recognition	Refined Petroleum Products Revenue We sell jet fuel in nearby markets, and our intermediate products, including liquefied petroleum gas, naphtha, heavy oil-based mud blendstock (“HOBM”), and atmospheric gas oil (“AGO”), to wholesalers and nearby refineries for further blending and processing. Revenue from refined petroleum products sales is recognized when title passes. Title passage occurs when refined petroleum products are sold or delivered in accordance with the terms of the respective sales agreements. Revenue is recognized when sales prices are fixed or determinable and collectability is reasonably assured. Customers assume the risk of loss when title is transferred. Transportation, shipping, and handling costs incurred are included in cost of refined products sold. Excise and other taxes that are collected from customers and remitted to governmental authorities are not included in revenue. Tank Rental Revenue Tank rental fees are invoiced monthly in accordance with the terms of the related lease agreement and recognized in revenue as earned. Easement Revenue Land easement revenue is recognized monthly as earned and is included in other income. Pipeline Transportation Revenue Revenue from our pipeline operations is derived from fee-based contracts and is typically based on transportation fees per unit of volume transported multiplied by the volume delivered. Revenue is recognized when volumes have been physically delivered for the customer through the pipeline. Deferred Revenue On February 5, 2014, we entered into an Asset Sale Agreement (the “Purchase Agreement”) with WBI Energy Midstream, LLC, a Colorado limited liability company (“WBI”), whereby we reacquired WBI’s 1/6th interest in the Blue Dolphin Pipeline System, the Galveston Area Block 350 Pipeline, and the Omega Pipeline (the “Pipeline Assets”) effective October 31, 2013. Pursuant to the Purchase Agreement, WBI paid us $100,000 in cash, and a surety company $850,000 in cash as collateral for supplemental pipeline bonds for our benefit in exchange for the payment and discharge of any and all payables, claims, and obligations related to the Pipeline Assets. We recorded the amount received for our benefit for the supplemental pipeline bonds as deferred revenue. The deferred revenue is being recognized on a straight-line basis through December 31, 2018, the expected retirement date of the assets that the supplemental pipeline bonds secure.
Income Taxes	We account for income taxes under FASB ASC guidance related to income taxes, which requires recognition of income taxes based on amounts payable with respect to the current year and the effects of deferred taxes for the expected future tax consequences of events that have been included in our financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial accounting and tax basis of assets and liabilities, as well as for operating losses and tax credit carryforwards using enacted tax rates in effect for the year in which the differences are expected to reverse. As of each reporting date, management considers new evidence, both positive and negative, to determine the realizability of deferred tax assets. Management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized, which is dependent upon the generation of future taxable income prior to the expiration of any net operating loss (“NOL”) carryforwards. When management determines that it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce deferred tax assets. The guidance also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, as well as guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. See “Note (17) Income Taxes” of this report for further information related to income taxes.
Impairment or Disposal of Long-Lived Assets	In accordance with FASB ASC guidance on accounting for the impairment or disposal of long-lived assets, we periodically evaluate our long-lived assets for impairment. Additionally, we evaluate our long-lived assets when events or circumstances indicate that the carrying value of these assets may not be recoverable. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset or group of assets is recognized. Significant management judgment is required in the forecasting of future operating results that are used in the preparation of projected cash flows and, should different conditions prevail or judgments be made, material impairment charges could be necessary.
Asset Retirement Obligations	FASB ASC guidance related to asset retirement obligations (“AROs”) requires that a liability for the discounted fair value of an ARO be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted towards its future value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Management has concluded that there is no legal or contractual obligation to dismantle or remove the refinery and facilities. Further, management believes that these assets have indeterminate lives under FASB ASC guidance for estimating AROs because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of these assets, we will estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using present value techniques. We recorded an ARO liability related to future asset retirement costs associated with dismantling, relocating, or disposing of our offshore platform, pipeline systems, and related onshore facilities, as well as for plugging and abandoning wells and restoring land and sea beds. We developed these cost estimates for each of our assets based upon regulatory requirements, structural makeup, water depth, reservoir characteristics, reservoir depth, equipment demand, current retirement procedures, and construction and engineering consultations. Because these costs typically extend many years into the future, estimating future costs are difficult and require management to make judgments that are subject to future revisions based upon numerous factors, including changing technology, political, and regulatory environments. We review our assumptions and estimates of future abandonment costs on an annual basis. See “Note (12) Asset Retirement Obligations” of this report for additional information related to our AROs.
Computation of Earnings Per Share	We apply the provisions of FASB ASC guidance for computing earnings per share (“EPS”). The guidance requires the presentation of basic EPS, which excludes dilution and is computed by dividing net income available to common stockholders by the weighted-average number of shares of common stock outstanding for the period. The guidance requires dual presentation of basic EPS and diluted EPS on the face of our consolidated statements of income and requires a reconciliation of the numerators and denominators of basic EPS and diluted EPS. Diluted EPS is computed by dividing net income available to common stockholders by the diluted weighted average number of common shares outstanding, which includes the potential dilution that could occur if securities or other contracts to issue shares of common stock were converted to common stock that then shared in the earnings of the entity. The number of shares related to options, warrants, restricted stock, and similar instruments included in diluted EPS is based on the “Treasury Stock Method” prescribed in FASB ASC guidance for computation of EPS. This method assumes theoretical repurchase of shares using proceeds of the respective stock option or warrant exercised, and, for restricted stock, the amount of compensation cost attributed to future services that has not yet been recognized and the amount of any current and deferred tax benefit that would be credited to additional paid-in-capital upon the vesting of the restricted stock, at a price equal to the issuer’s average stock price during the related earnings period. Accordingly, the number of shares includable in the calculation of EPS in respect of the stock options, warrants, restricted stock, and similar instruments is dependent on this average stock price and will increase as the average stock price increases. See “Note (18) Earnings Per Share” for additional information related to EPS.
Stock-Based Compensation	In accordance with FASB ASC guidance for stock-based compensation, share-based payments to personnel, including grants of restricted stock units, are measured at fair value as of the date of grant and are expensed in our consolidated statements of income over the service period (generally the vesting period).
Treasury Stock	We account for treasury stock under the cost method. When treasury stock is re-issued, the net change in share price subsequent to acquisition of the treasury stock is recognized as a component of additional paid-in-capital in our consolidated balance sheets. See “Note (14) Treasury Stock” for additional disclosures related to treasury stock.
Reclassification	We have reclassified certain insignificant prior period amounts related to our tank rental revenue to conform to our 2015 presentation.
New Pronouncements Issued but Not Yet Effective	FASB issues an Accounting Standards Update (“ASU”) to communicate changes to the FASB ASC, including changes to non-authoritative SEC content. The following are recently issued, but not yet effective, accounting standards that may have an effect on our consolidated financial position, results of operations, or cash flows: • Revenue from Contracts with Customers In August 2015, FASB issued R evenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, • Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern • Inventory (Topic 330): Simplifying the Measurement of Inventory • Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs • Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements Other new pronouncements issued but not effective until after September 30, 2015 are not expected to have a material impact on our financial position, results of operations or liquidity.

4. Business Segment Informati28

4. Business Segment Information (Tables)	9 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
Business segment reporting	Business segment information for the three months ended September 30, 2015 and 2014 (and at September 30, 2015 and 2014), was as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 55,210,962 $ 45,925 $ - $ 55,256,887 $ 88,129,273 $ 56,900 $ - $ 88,186,173 Less: cost of operations(1) (51,444,705 ) (114,675 ) (236,816 ) (51,796,196 ) (85,261,533 ) (110,872 ) (274,674 ) (85,647,079 ) Other non-interest income(2) - 62,500 660,000 722,500 - - - - Adjusted EBITDA 3,766,257 (6,250 ) 423,184 4,183,191 2,867,740 (53,972 ) (274,674 ) 2,539,094 Less: JMA Profit Share(3) (1,435,376 ) - - (1,435,376 ) (1,094,383 ) - - (1,094,383 ) EBITDA $ 2,330,881 $ (6,250 ) $ 423,184 $ 1,773,357 $ (53,972 ) $ (274,674 ) Depletion, depreciation and amortization (414,837 ) (393,871 ) Interest expense, net (380,342 ) (212,594 ) Income before income taxes 1,952,636 838,246 Income tax expense (688,403 ) (22,199 ) Net income $ 1,264,233 $ 816,047 Capital expenditures $ 3,640,801 $ - $ - $ 3,640,801 $ 815,849 $ - $ - $ 815,849 Identifiable assets(4) $ 79,442,106 $ 3,303,803 $ 3,405,977 $ 86,151,886 $ 57,520,835 $ 2,998,619 $ 523,533 $ 61,042,987 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue and the Grynberg Settlement Agreement. See “Part 1, Item 1. Financial Statements - Note (21) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this report for further discussion related to FLNG and Grynberg. (3) The Joint Marketing Agreement profit share (the “JMA Profit Share”) represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (21) Commitments and Contingencies – Genesis Agreements” and “Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for further discussion related to the Joint Marketing Agreement. (4) Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable, and recorded net assets. Business segment information for the nine months ended September 30, 2015 and 2014 (and at September 30, 2015 and 2014), was as follows: Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Segment Segment Refinery Pipeline Corporate & Refinery Pipeline Corporate & Operations Transportation Other Total Operations Transportation Other Total Revenue from operations $ 175,690,968 $ 119,882 $ - $ 175,810,850 $ 311,786,529 $ 178,793 $ - $ 311,965,322 Less: cost of operations(1) (160,208,576 ) (296,291 ) (928,331 ) (161,433,198 ) (297,956,882 ) (355,645 ) (973,154 ) (299,285,681 ) Other non-interest income(2) - 187,500 660,000 847,500 - 208,333 - 208,333 Adjusted EBITDA 15,482,392 11,091 (268,331 ) 15,225,152 13,829,647 31,481 (973,154 ) 12,887,974 Less: JMA Profit Share(3) (4,812,674 ) - - (4,812,674 ) (2,334,487 ) - - (2,334,487 ) EBITDA $ 10,669,718 $ 11,091 $ (268,331 ) $ 11,495,160 $ 31,481 $ (973,154 ) Depletion, depreciation and amortization (1,217,005 ) (1,175,643 ) Interest expense, net (1,313,247 ) (630,175 ) Income before income taxes 7,882,226 8,747,669 Income tax expense (2,778,750 ) (298,792 ) Net income $ 5,103,476 $ 8,448,877 Capital expenditures $ 9,900,295 $ - $ - $ 9,900,295 $ 1,145,720 $ - $ - $ 1,145,720 Identifiable assets(4) $ 79,442,106 $ 3,303,803 $ 3,405,977 $ 86,151,886 $ 57,520,835 $ 2,998,619 $ 523,533 $ 61,042,987 (1) Operation cost within the Refinery Operations and Pipeline Transportation segments includes related general, administrative, and accretion expenses. Operation cost within Corporate and Other includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense. (2) Other non-interest income reflects FLNG easement revenue and the Grynberg Settlement Agreement. See “Part 1, Item 1. Financial Statements - Note (21) Commitments and Contingencies – FLNG Master Easement Agreement and Grynberg Settlement Agreement” of this report for further discussion related to FLNG and Grynberg. (3) The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See “Note (21) Commitments and Contingencies – Genesis Agreements” and “Part 1, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Relationship with Genesis” of this report for further discussion related to the Joint Marketing Agreement. (4) Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable, and recorded net assets.

5. Prepaid Expenses and Other29

5. Prepaid Expenses and Other Current Assets (Tables)	9 Months Ended
	Sep. 30, 2015
Prepaid Expenses And Other Current Assets Tables
Prepaid balances	Prepaid expenses and other current assets consisted of the following: September 30, December 31, 2015 2014 Prepaid related party operating expenses $ 712,688 $ - Prepaid insurance 196,305 156,558 Unrealized hedging gains 133,150 495,900 Prepaid listing fees 3,750 15,000 Prepaid professional fees - 104,000 $ 1,045,893 $ 771,458

6. Deposits (Tables)

6. Deposits (Tables)	9 Months Ended
	Sep. 30, 2015
Deposits Tables
Deposit balances	Deposits consisted of the following: September 30, December 31, 2015 2014 Construction deposits $ 300,000 $ - Equipment deposits 100,463 48,785 Utility deposits 10,250 10,250 Rent deposits 9,463 9,463 $ 420,176 $ 68,498

7. Inventory (Tables)

7. Inventory (Tables)	9 Months Ended
	Sep. 30, 2015
Inventory Disclosure [Abstract]
Inventory	Inventory consisted of the following: September 30, December 31, 2015 2014 HOBM $ 3,044,646 $ 124,176 Jet fuel 1,557,847 2,631,546 AGO 403,875 224,007 Naphtha 362,049 194,688 Chemicals 216,208 - Crude oil and condensate 19,041 19,041 Propane 12,817 - LPG mix 4,344 7,193 $ 5,620,827 $ 3,200,651

8. Property, Plant and Equipm32

8. Property, Plant and Equipment, Net (Tables)	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
Property and equipment	Property, plant and equipment, net, consisted of the following: [Missing Graphic Reference]

11. Accrued Expenses and Othe33

11. Accrued Expenses and Other Current Liabilities (Tables)	9 Months Ended
	Sep. 30, 2015
Accrued Expenses And Other Current Liabilities Tables
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities consisted of the following: September 30, December 31, 2015 2014 Excise and income taxes payable $ 1,489,921 $ 1,228,411 Other payable 175,634 149,962 Genesis JMA Profit Share payable 162,470 521,739 Property taxes 92,002 - Board of director fees payable 85,179 345,000 Transportation and inspection - 190,000 Unearned revenue - 252,500 Insurance - 96,092 $ 2,005,206 $ 2,783,704

12. Asset Retirement Obligati34

12. Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	AROs on a roll-forward basis were as follows: September 30, December 31, 2015 2014 Asset retirement obligations, at the beginning of the period $ 1,866,770 $ 1,597,661 New asset retirement obligations and adjustments 49 300,980 Liabilities settled (58,459 ) (243,866 ) Accretion expense 158,655 211,995 1,967,015 1,866,770 Less: current portion of asset retirement obligations (38,644 ) (85,846 ) Long-term asset retirement obligations, at the end of the period $ 1,928,371 $ 1,780,924

13. Long-Term Debt (Tables)

13. Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long Term Debt	Long-term debt consisted of the following: September 30, December 31, 2015 2014 Term Loan Due 2034 $ 24,822,362 $ - Term Loan Due 2016 3,000,000 - Notre Dame Debt 1,300,000 1,300,000 Term Loan Due 2017 1,109,962 1,638,898 Capital Leases 347,236 466,401 Refinery Note - 8,648,980 30,579,560 12,054,279 Less: current portion of long-term debt (1,631,539 ) (1,245,476 ) $ 28,948,021 $ 10,808,803
Schedule of summary of equipment held under long-term capital leases	The following is a summary of equipment held under long-term capital leases: September 30, December 31, 2015 2014 Boiler equipment $ 538,598 $ 538,598 Less: accumulated depreciation - - $ 538,598 $ 538,598

15. Concentration of Risk (Tabl

15. Concentration of Risk (Tables)	9 Months Ended
	Sep. 30, 2015
Concentration Of Risk Tables
Percentages of all refined petroleum products sales to total sales	The following table summarizes total refined petroleum product sales by distillation (from light to heavy): Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 LPG mix $ 617,715 1.1 % $ 146,452 0.2 % $ 909,207 0.5 % $ 670,473 0.2 % Naphtha 11,218,381 20.4 % 19,195,974 21.8 % 38,048,064 21.8 % 73,061,235 23.5 % Jet fuel 17,782,534 32.4 % 25,978,551 29.6 % 51,713,507 29.6 % 65,616,193 21.1 % NRLM - 0.0 % - 0.0 % - 0.0 % 62,729,476 20.2 % HOBM 9,609,536 17.5 % 22,094,185 25.1 % 40,640,975 23.2 % 29,321,261 9.4 % Reduced Crude 50,407 0.1 % - 0.0 % 50,407 0.0 % - 0.0 % AGO 15,645,497 28.5 % 20,431,595 23.3 % 43,468,132 24.9 % 79,540,343 25.6 % $ 54,924,070 100.0 % $ 87,846,757 100.0 % $ 174,830,292 100.0 % $ 310,938,981 100.0 %

17. Income Taxes (Tables)

17. Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income tax benefit (expense)	Our income tax expense consisted of the following: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Current: Federal $ (37,620 ) $ (1,395 ) $ (122,863 ) $ (152,759 ) State (36,102 ) (20,804 ) (148,656 ) (146,033 ) Deferred: Federal (614,681 ) - (2,507,231 ) - State - - - - $ (688,403 ) $ (22,199 ) $ (2,778,750 ) $ (298,792 )
Deferred tax assets and deferred tax liabilities	The following table shows significant components of our deferred tax assets and liabilities: September 30, December 31, 2015 2014 Deferred tax assets: Net operating loss and capital loss carryforwards $ 8,221,505 $ 10,067,144 Start-up costs (Nixon Facility) 1,545,033 1,648,036 Asset retirement obligations liability/deferred revenue 859,819 869,821 AMT credit and other 236,389 85,467 Total deferred tax assets 10,862,746 12,670,468 Deferred tax liabilities: Fair market value adjustments (46,116 ) (46,116 ) Unrealized hedges (45,271 ) (168,606 ) Basis differences in property and equipment (5,220,754 ) (4,425,318 ) Total deferred tax liabilities (5,312,141 ) (4,640,040 ) Deferred tax assets, net 5,550,605 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,280,283 $ 5,760,106
Current and noncurrent deferred tax assets (liabilities)	The following table shows our current and noncurrent deferred tax assets (liabilities): September 30, December 31, 2015 2014 Current deferred tax liabilities $ 5,162,781 $ (168,236 ) Noncurrent deferred tax assets, net 387,824 8,198,664 Deferred tax assets, net 5,550,605 8,030,428 Valuation allowance (2,270,322 ) (2,270,322 ) $ 3,280,283 $ 5,760,106

18. Earnings Per Share (Tables)

18. Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Earnings per share	The following table provides reconciliation between basic and diluted income per share: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Net income $ 1,264,233 $ 816,047 $ 5,103,476 $ 8,448,877 Basic and diluted income per share $ 0.12 $ 0.08 $ 0.49 $ 0.81 Basic and Diluted Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock 10,453,802 10,446,218 10,451,168 10,439,684

19. Fair Value Measurement (Tab

19. Fair Value Measurement (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurement	The following table represents our assets and liabilities measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 and the basis for the measurement: Fair Value Measurement at September 30, 2015 Using Financial assets (liabilities): Carrying Value at September 30, 2015 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 133,150 $ 133,150 $ - $ - Fair Value Measurement at December 31, 2014 Using Financial assets (liabilities): Carrying Value at December 31, 2014 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity contracts $ 495,900 $ 495,900 $ - $ -

20. Inventory Risk Management (

20. Inventory Risk Management (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional volume of outstanding contracts by type of instrument	The information presents the notional volume of open commodity instruments by type and year of maturity (volumes in barrels): Notional Contract Volumes by Year of Maturity Inventory positions (futures): 2015 2016 2017 Refined petroleum products and crude oil - net short positions 155,000 - -
Fair value amounts of derivative instruments	The following table provides the location and fair value amounts of derivative instruments that are reported in our consolidated balance sheets at September 30, 2015 and December 31, 2014: Fair Value Asset Derivatives Balance Sheets Location September 30, 2015 December 31, 2014 Prepaid expenses and other current assets (accrued expenses and other Commodity contracts current liabilities) $ 133,150 $ 495,900
Effect of derivative instruments	The following table provides the effect of derivative instruments in our consolidated statements of income for the three months ended September 30, 2015 and 2014: Gain (Loss) Recognized Three Months Ended September 30, Nine Months Ended September 30, Derivatives Statements of Operations Location 2015 2014 2015 2014 Commodity contracts Cost of refined products sold $ 2,205,291 $ 396,271 $ 1,762,582 $ (12,438 )

3. Significant Accounting Pol41

3. Significant Accounting Policies (Details Narrative) - USD ($)	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Cash and cash equivalents	$ 1,518,359	$ 1,293,233	$ 1,182,475	$ 434,717
Restricted cash	5,834,197	$ 1,008,514
Restricted cash, noncurrent	11,277,441
FDIC limit per depositer	250,000
Cash balances in excess of the FDIC insurance limit per depositor	18,017,488	$ 1,113,977
Acquisition-related intangible asset	$ 303,346	$ 303,346

4. Business Segment Informati42

4. Business Segment Information (Details) - USD ($)		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenue from operations		$ 55,256,887	$ 88,186,173	$ 175,810,850	$ 311,965,322
Income tax expense		688,403	22,199	2,778,750	298,792
Net income		$ 1,264,233	$ 816,047	5,103,476	8,448,877
Refinery Operations [Member]
Revenue from operations				175,690,968	311,786,529
Less: cost of operations	[1]			$ (160,208,576)	$ (297,956,882)
Other non-interest income	[2]
Adjusted EBITDA				$ 15,482,392	$ 13,829,647
Less: JMA Profit Share	[3]			(4,812,674)	(2,334,487)
EBITDA				10,669,718	11,495,160
Capital expenditures				9,900,295	1,145,720
Identifiable assets	[4]			79,442,106	57,520,835
Pipeline Transportation [Member]
Revenue from operations				119,882	178,793
Less: cost of operations	[1]			(296,291)	(355,645)
Other non-interest income	[2]			187,500	208,333
Adjusted EBITDA				$ 11,091	$ 31,481
Less: JMA Profit Share	[3]
EBITDA				$ 11,091	$ 31,481
Capital expenditures
Identifiable assets	[4]			$ 3,303,803	$ 2,998,619
Corporate and Other [Member]
Revenue from operations
Less: cost of operations	[1]			$ (928,331)	$ (973,154)
Other non-interest income	[2]			660,000
Adjusted EBITDA				$ (268,331)	$ (973,154)
Less: JMA Profit Share	[3]
EBITDA				$ (268,331)	$ (973,154)
Capital expenditures
Identifiable assets	[4]			$ 3,405,977	$ 523,533
Total
Revenue from operations				175,810,850	311,965,322
Less: cost of operations	[1]			(161,433,198)	(299,285,681)
Other non-interest income	[2]			847,500	208,333
Adjusted EBITDA				15,225,152	12,887,974
Less: JMA Profit Share	[3]			$ (4,812,674)	(2,334,487)
EBITDA
Depletion, depreciation and amortization				$ (1,217,005)	(1,175,643)
Interest expense, net				(1,313,247)	(630,175)
Income before income taxes				7,882,226	8,747,669
Income tax expense				(2,778,750)	(298,792)
Net income				5,103,476	8,448,877
Capital expenditures				9,900,295	1,145,720
Identifiable assets	[4]			$ 86,151,886	$ 61,042,987
[1]	Operation cost within the "Refinery Operations" and "Pipeline Transportation" segments includes related general, administrative, and accretion expenses. Operation cost within "Corporate and Other" includes general and administrative expenses associated with corporate maintenance costs, such as accounting fees, director fees, and legal expense.
[2]	Other non-interest income reflects FLNG easement revenue and the Grynberg Settlement Agreement. See "Part 1, Item 1. Financial Statements - Note (21) Commitments and Contingencies - FLNG Master Easement Agreement and Grynberg Settlement Agreement" of this report for further discussion related to FLNG and Grynberg.
[3]	The JMA Profit Share represents the GEL Profit Share plus the Performance Fee for the period pursuant to the Joint Marketing Agreement. See "Note (21) Commitments and Contingencies - Genesis Agreements" and "Part 1, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Relationship with Genesis" of this report for further discussion related to the Joint Marketing Agreement.
[4]	Identifiable assets contain related legal obligations of each business segment including cash, accounts receivable, and recorded net assets.

5. Prepaid Expenses and Other43

5. Prepaid Expenses and Other Current Assets (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Prepaid Expenses And Other Current Assets Details
Prepaid related party operating expenses	$ 712,688
Prepaid insurance	196,305	$ 156,558
Unrealized hedging gains	133,150	495,900
Prepaid listing fees	3,750	15,000
Prepaid professional fees		104,000
Prepaid Expenses, Net	$ 1,045,893	$ 771,458

6. Deposits (Details)

6. Deposits (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Deposits Details
Construction deposits	$ 300,000
Equipment deposits	100,463	$ 48,785
Utility deposits	10,250	10,250
Rent deposits	9,463	9,463
Total Deposits	$ 420,176	$ 68,498

7. Inventory (Details)

7. Inventory (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
HOBM	$ 3,044,646	$ 124,176
Jet fuel	1,557,847	2,631,546
AGO	403,875	224,007
Naphtha	362,049	194,688
Chemicals	216,208
Crude oil and condensate	19,041	19,041
Propane	12,817
LPG mix	4,344	7,193
Inventories, Net	$ 5,620,827	$ 3,200,651

8. Property, Plant and Equipm46

8. Property, Plant and Equipment, Net (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Property Plant And Equipment Net Details
Refinery and facilities		$ 36,462,451
Pipelines and facilities		2,127,207
Onshore separation and handling facilities		325,435
Land		602,938
Other property and equipment		597,064
Property, Plant and Equipment, Gross		40,115,095
Less: Accumulated depletion, depreciation and amortization		(4,586,575)
Property, Plant and Equipment less depreciation		35,528,520
Construction in progress		1,842,555
Property, Plant and Equipment, Net	$ 46,054,365	$ 37,371,075

9. Debt Issue Costs (Details Na

9. Debt Issue Costs (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Payables and Accruals [Abstract]
Accumulated amortization	$ 22,781		$ 22,781		$ 211,244
Amortization expense			517,652	$ 25,350
Debt issuance costs	1,296,480		1,296,480		$ 479,737
Interest expense including Amortization expense	$ 17,086	$ 8,450
Refinancing debt owed to American First National Bank			$ 456,287

10. Accounts Payable, Related48

10. Accounts Payable, Related Party (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Accounts Payable Related Party Details Narrative
Expense for service	$ 2,953,528	$ 2,496,514	$ 8,420,650	$ 8,092,738
Prepaid related party operating expenses	$ 712,688		$ 712,688
Accounts payable, related party					$ 1,174,168

11. Accrued Expenses and Othe49

11. Accrued Expenses and Other Current Liabilities (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Accrued Expenses And Other Current Liabilities Details
Excise and income taxes payable	$ 1,489,921	$ 1,228,411
Other payable	175,634	149,962
Genesis JMA Profit Share payable	162,470	521,739
Property taxes	92,002
Board of director fees payable	85,179	345,000
Transportation and inspection		190,000
Unearned revenue		252,500
Insurance		96,092
Accrued Expenses and Other Current Liabilities, Net	$ 2,005,206	$ 2,783,704

12. Asset Retirement Obligati50

12. Asset Retirement Obligations (Details) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Asset Retirement Obligations Details
Asset retirement obligations, at the beginning of the period			$ 1,866,770	$ 1,597,661	$ 1,597,661
New asset retirement obligations and adjustments			49		300,980
Liabilities settled			(58,459)		(243,866)
Accretion expense	$ 52,720	$ 53,731	158,655	$ 158,264	211,995
Asset retirement obligations	1,967,015		1,967,015		1,866,770
Less: current portion of asset retirement obligations	(38,644)		(38,644)		(85,846)
Long-term asset retirement obligations, at the end of the period	$ 1,928,371		$ 1,928,371		$ 1,780,924

13. Long-Term Debt (Details)

13. Long-Term Debt (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Term Loan Due 2034	$ 24,822,362
Term Loan Due 2016	3,000,000
Notre Dame Debt	1,300,000	$ 1,300,000
Term Loan Due 2017	1,109,962	1,638,898
Capital leases	347,236	466,401
Refinery Note		8,648,980
Total	30,579,560	12,054,279
Less: Current portion of long-term debt	(1,631,539)	(1,245,476)
Long term debt	$ 28,948,021	$ 10,808,803

13. Long-Term Debt (Details 1)

13. Long-Term Debt (Details 1) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Boiler equipment	$ 538,598	$ 538,598
Less: Accumulated depreciation
Capital lease obligation	$ 538,598	$ 538,598

13. Long-Term Debt (Details Nar

13. Long-Term Debt (Details Narrative) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Principal balance outstanding	$ 28,948,021	$ 10,808,803
Term Loan Due 2034 [Member]
Interest accrued	33,102	0
Principal balance outstanding	24,822,362	0
Notre Dame Debt [Member]
Interest accrued	1,430,371	1,274,789
Principal balance outstanding	1,300,000	1,300,000
Term Loan Due 2017 [Member]
Interest accrued	5,550	8,470
Principal balance outstanding	1,109,962	1,638,898
Capital Leases [Member]
Interest accrued	2,988	0
Principal balance outstanding	347,236	466,401
Term Loan Due 2016 [Member]
Interest accrued	15,500	0
Principal balance outstanding	$ 3,000,000	$ 0

14. Treasury Stock (Details Nar

14. Treasury Stock (Details Narrative) - shares	Sep. 30, 2015	Dec. 31, 2014
Income Taxes Details 3
Treasury stock	150,000	150,000

15. Concentration of Risk (Deta

15. Concentration of Risk (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Total refined petroleum product sales	$ 54,924,070	$ 87,846,757	$ 174,830,292	$ 310,938,981
Concentration Risk	100.00%	100.00%	100.00%	100.00%
LPG mix
Total refined petroleum product sales	$ 617,715	$ 146,452	$ 909,207	$ 670,473
Concentration Risk	1.10%	0.20%	0.50%	0.20%
Naphtha
Total refined petroleum product sales	$ 11,218,381	$ 19,195,974	$ 38,048,064	$ 73,061,235
Concentration Risk	20.40%	21.80%	21.80%	23.50%
Jet Fuel
Total refined petroleum product sales	$ 17,782,534	$ 25,978,551	$ 51,713,507	$ 65,616,193
Concentration Risk	32.40%	29.60%	29.60%	21.10%
NRLM
Total refined petroleum product sales				$ 62,729,476
Concentration Risk	0.00%	0.00%	0.00%	20.20%
HOBM
Total refined petroleum product sales	$ 9,609,536	$ 22,094,185	$ 40,640,975	$ 29,321,261
Concentration Risk	17.50%	25.10%	23.20%	9.40%
Reduced crude
Total refined petroleum product sales	$ 50,407		$ 50,407
Concentration Risk	0.10%	0.00%	0.00%	0.00%
AGO
Total refined petroleum product sales	$ 15,645,497	$ 20,431,595	$ 43,468,132	$ 79,540,343
Concentration Risk	28.50%	23.30%	24.90%	25.60%

15. Concentration of Risk (De56

15. Concentration of Risk (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Concentration Risk	100.00%	100.00%	100.00%	100.00%
Sales Revenue [Member] | Five customers [Member]
Concentration Risk	81.00%
Sales Revenue [Member] | Three customers [Member]
Concentration Risk		71.00%	55.00%
Sales Revenue [Member] | Four customers [Member]
Concentration Risk				84.00%
Account receivable [Member] | Five customers [Member]
Accounts receivable	$ 5,700,000
Account receivable [Member] | Three customers [Member]
Accounts receivable		$ 6,400,000	$ 4,400,000
Account receivable [Member] | Four customers [Member]
Accounts receivable				$ 7,700,000

16. Leases (Details Narrative)

16. Leases (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Leases Details Narrative
Rent expense	$ 29,857	$ 26,129	$ 112,746	$ 77,787

17. Income Taxes (Details)

17. Income Taxes (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Current:
Federal	$ (37,620)	$ (1,395)	$ (122,863)	$ (152,759)
State	(36,102)	$ (20,804)	(148,656)	$ (146,033)
Deferred:
Federal	$ (614,681)		$ (2,507,231)
State
Income tax benefit (expense)	$ (688,403)	$ (22,199)	$ (2,778,750)	$ (298,792)

17. Income Taxes (Details 1)

17. Income Taxes (Details 1) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Deferred tax assets:
Net operating loss and capital loss carryforwards	$ 8,221,505	$ 10,067,144
Start-up costs (Nixon Facility)	1,545,033	1,648,036
Asset retirement obligations liability/deferrred revenue	859,819	869,821
AMT credit and other	236,389	85,467
Total deferred tax assets	10,862,746	12,670,468
Deferred tax liabilities:
Fair market value adjustments	(46,116)	(46,116)
Unrealized hedges	(45,271)	(168,606)
Basis differences in property and equipment	(5,220,754)	(4,425,318)
Total deferred tax liabilities	(5,312,141)	(4,640,040)
Deferred tax assets, net	5,550,605	8,030,428
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 3,280,283	$ 5,760,106

17. Income Taxes (Details 2)

17. Income Taxes (Details 2) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
IncomeTaxesDetails3Abstract
Current deferred tax liabilities	$ (2,892,459)
Noncurrent deferred tax assets, net	387,824	$ 8,198,664
Deferred tax assets, net	5,550,605	8,030,428
Valuation allowance	(2,270,322)	(2,270,322)
Deferred tax assets and liabilities, net	$ 3,280,283	$ 5,760,106

17. Income Taxes (Details Narra

17. Income Taxes (Details Narrative)	Sep. 30, 2015USD ($)
Income Taxes Details 1
Amount of NOLs	$ 9,600,000
Post-merger NOLs	$ 7,900,000

18. Earnings per share (Details

18. Earnings per share (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Abstract]
Net income	$ 1,264,233	$ 816,047	$ 5,103,476	$ 8,448,877
Basic and diluted income per share	$ 0.12	$ 0.08	$ 0.49	$ 0.81
Basic and diluted
Weighted average number of shares of common stock outstanding and potential dilutive shares of common stock	10,453,802	10,446,218	10,451,168	10,439,684

19. Fair Value Measurement (Det

19. Fair Value Measurement (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Financial assets (liabilties):
Commodity contracts	$ 133,150	$ 495,900
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) [Member]
Financial assets (liabilties):
Commodity contracts	$ 133,150	$ 495,900
Significant Other Observable Inputs (Level 2) [Member]
Financial assets (liabilties):
Commodity contracts
Significant Unobservable Inputs (Level 3) [Member]
Financial assets (liabilties):
Commodity contracts

19. Fair Value Measurement (D64

19. Fair Value Measurement (Details Narrative) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Fair Value Measurement Details Narrative
Fair value of long term debt and short-term notes payable	$ 30,579,560	$ 12,054,279

20. Inventory Risk Management65

20. Inventory Risk Management (Details) - Refined products - net short (long) positions	Sep. 30, 2015shares
Volume in Thousands of barrels
Notional Contract Volumes 2015	155,000
Notional Contract Volumes 2016
Notional Contract Volumes 2017

20. Inventory Risk Management66

20. Inventory Risk Management (Details 1) - Commodity Contracts [Member] - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Prepaid expenses and other current assets (accrued expenses and other current liabilities)	$ 133,150		$ 133,150		$ 495,900
Cost of refined petroleum products sold	$ 2,205,291	$ 396,271	$ 1,762,582	$ (12,438)